1. Field of the Invention
Embodiments disclosed herein generally relate to annular blowout preventers used in the oil and gas industry. Specifically, embodiments selected relate to a new type of retrievable stripping sleeve for use with an annular type blowout preventer or similar device. ‘Stripping’ is defined as the act of pushing or pulling tubular's through an annular preventer element under pressure or without pressure with the stripping element closed around the tubular.
2. Background Art
Well control is an important aspect of oil and gas exploration. When drilling a well, for example, in oil and gas exploration applications, safety devices must be put in place to prevent injury to personnel and damage to equipment resulting from unexpected events associated with the drilling activities.
Drilling wells in oil and gas exploration involves penetrating a variety of subsurface geologic structures, or “layers.” Occasionally, a wellbore will penetrate a layer having a formation pressure substantially higher than the pressure maintained in the wellbore. When this occurs, the well is said to have “taken a kick.” The pressure increase associated with the kick is generally produced by an influx of formation fluids (which may be a liquid, a gas, or a combination thereof) into the wellbore. The relatively high pressure kick tends to propagate from a point of entry in the wellbore then uphole (from a high pressure region to a low pressure region). If the kick is allowed to reach the surface, drilling fluid, well tools, and other drilling structures may be blown out of the wellbore. These “blowouts” may result in catastrophic destruction of the drilling equipment (including, for example, the drilling rig) and substantial injury or death of rig personnel.
Because of the risk of blowouts, blowout preventers (“BOPs”) are typically installed at the surface or on the sea floor in deep water drilling arrangements to effectively seal a wellbore until active measures can be taken to control the kick. BOPs may be activated so that kicks are adequately controlled and “circulated out” of the system. There are several types of BOPs, one common type of which is an annular blowout preventer.
Annular BOPs typically comprise annular, elastomeric “packing units” that may be activated to encapsulate drillpipe and well tools to completely seal about a wellbore. In situations where no drillpipe or well tools are within the central bore or passage of the packing unit, the packing unit can be compressed to such an extent that the central bore or passage is entirely closed, acting as a valve on the wellbore. Typically, packing units are used in the case of sealing about a drillpipe, in which the packing unit can be quickly compressed, ether manually or automatically, to effect a seal about the pipe to prevent a well from blowing out.
An example of an annular BOP having a packing unit is disclosed in U.S. Pat. No. 2,609,836, (“Knox”) and incorporated herein by reference. The packing unit includes a plurality of metal inserts embedded in an elastomeric body. The metal inserts are typically spaced equal circumferential distances from one another about a longitudinal axis of the packing unit. The inserts provide structural support for the elastomeric body when the packing unit is radially compressed to seal against the well pressure. Upon compression of the packing unit about a drillpipe, or upon itself, to seal against the wellbore pressure, the elastomeric body is squeezed radially inwardly, causing the metal inserts to move radially inwardly as well.
FIG. 1 shows an example of a prior art ‘wedge type’ annular BOP 10 including a housing 12. The annular BOP 10 has a central bore or passage 14 extending from top to bottom and is disposed about a longitudinal axis. A packing unit 16 is disposed within the annular BOP 10 about the longitudinal axis A. The packing unit 16 includes an elastomeric annular body 18 and a plurality of metallic inserts 30. The metallic inserts 30 are disposed within the elastomeric annular body 18 of the packing unit 16 and distributed at equal circumferential distances from one another about the longitudinal axis A. The metallic inserts 30 each comprise an upper finger 30a and a lower finger 30b joined by a metal stabilising plate, the elastomeric body 18 lying between the upper 30a and lower 30b fingers. The packing unit 16 includes a generally central bore or passage 20 concentric; with the generally central bore or passage 14 of the BOP 10.
The annular BOP 10 is actuated by fluid pumped into a piston chamber in the housing 12 via first port 22. The fluid applies pressure to a piston 24, which moves the piston 24 upward. As the piston 24 moves upward, the piston 24 exerts a force on the packing unit 16 through a wedge face 26. The force exerted on the packing unit 16 from the wedge face 26 is directed upwards toward a removable head 28 of the annular BOP 10, and inwards toward the longitudinal axis A of the annular BOP 10. Because the packing unit 16 is retained against the removable head 28 of the annular BOP 10, the packing unit 16 does not displace upwardly from the force exerted on the packing unit 16 by the piston 24. The relaxed state of the packing unit 16 is shown in FIG. 2A.
However, the packing unit 16 does displace inwardly from the force from the piston 24, which compresses the packing unit 16 toward the longitudinal axis of the annular BOP 10. In the event a drill pipe 32 is located along the longitudinal axis A, with sufficient radial compression, the packing unit 16 will seal about the drill pipe 32 into a “closed position.” The closed position is shown in FIG. 2B. In the event a drill pipe is not present, the packing unit 16, with sufficient radial compression, will completely seal the generally central bore or passage 20. The annular BOP 10 goes through an analogous reverse movement when fluid is pumped into second port 34 into the piston chamber 36 and released from the first port 22. The fluid exerts a downward force on the piston 24, such that the wedge face 26 of the piston 24 allows the packing unit 16 to radially expand to an “open position.” The open position is shown in FIG. 2A. Further, the removable head 28 of the annular BOP 10 enables access to the packing unit 16, such that the packing unit 16 may be serviced or changed if necessary.
FIG. 3 is an example of a prior art ‘spherical type’ BOP 110 disposed about a longitudinal axis as disclosed in U.S. Pat. No. 3,667,721 (issued to Vujasinovic and incorporated by reference in its entirety). The spherical BOP 110 includes a lower housing 112 and an upper housing 128 releasably fastened together by a plurality of bolts 142. Typically, the upper housing 128 has a curved, semi-spherical inner surface 144. A packing unit 116 is disposed within the spherical BOP 110 about the longitudinal axis. The packing unit 116 includes a curved, elastomeric annular body 118 and curved metallic inserts 130 to correspond to the curved, semi-spherical inner surface 118 of the upper housing 128. The metallic inserts 130 are then distributed equal circumferential distances from one another within the curved, elastomeric annular body 118. The spherical BOP 110 may be actuated by fluid, similar to the annular BOP 10 of FIG. 1 as described above. FIGS. 4a and 4b show the open and closed positions respectively for the packing unit 116 on the drill pipe 32 for this spherical type BOP.
For all the above patents cited there is a common design feature in that the annular element is in direct contact with the drill pipe 32 or other tubular being sealed against. This gives a limited life of the packing element when used in ‘stripping’ operations. Stripping occurs when the pipe is moved into the wellbore or out of the wellbore under pressurized wellbore conditions with the element squeezed against the drillpipe. This results in substantial wear when the stripping is done for several thousand feet e.g. when pulling the drillbit all the way from bottom. This wear affects the integrity and sealability of the packing element.
For the annular BOP designs shown and all annular BOP designs on the market, it is required to dismantle the annular BOP to access the element and to change for a new element. This requires work to be stopped and in the case of repair to subsea annular BOPs can result in substantial non-productive time.
To overcome this substantial drawback of wear and maintenance a retrievable isolation tool 246 is proposed in U.S. Pat. No. 6,450,262, the isolation tool 246 being inserted at the level of the annular BOPS previously discussed.
In U.S. Pat. No. 6,450,262, in accordance with its illustrated and preferred embodiments, the isolation tool, as shown in FIG. 5 comprises a housing 248 adapted to be connected as a lower continuation of the riser and having a generally central bore or passage 214 through which the drill string 32 may extend during the drilling of the well, an annular recess 250 about the generally central passage, and a side port 252 below the recess for connecting the generally central passage to a mud return line extending alongside of the riser and leading to the surface. An insert packer 254 including a sleeve of elastomeric material 256 is adapted to be lowered into and raised from a landed position in the generally central passage opposite an actuator 258 within the housing recess 250 having a sleeve of elastomeric material 260 which, when retracted, occupies a position in which the insert packer 260 may be removed, forming a continuation of the generally central bore or passage so as to receive a drill string there through. When the insert packer 254 is in place, the actuator sleeve 258 is responsive to the supply of control fluid thereto from an outside source to engage and contract the sleeve 256 of the insert packer 254 about the drill string 32, so that the drilling fluid flowing upwardly in the annulus between the riser and drill string 32 is directed into the side port in the housing from the generally central bore or passage 214. In response to the exhaust of the control fluid, the insert packer sleeve 256 is free to expand to fully open the generally central passage and the insert 254 to be removed.
Also shown in FIG. 5, is a set of hydraulically operated pins 262 or bolts carried by the housing 248 so that, when moved inwardly, they provide a landing shoulder in the housing generally central bore or passage 214 to position the insert packer 254 opposite the actuator 258. A second set of hydraulically operated pins 264 carried by the housing are adapted to be moved into an annular groove 266 about the insert packer 254 to lock the insert packer in place to prevent its up or down movement in the generally central bore or passage 214. An upward pull on the drill string 32 can confirm the lock down of the insert packer 254. The annulus between the housing generally central bore or passage 214 and the insert packer 254 may be sealed off by contraction of the actuator sleeve 258 by means of fluid pressure supplied to the recess 250 about the sleeve to close about the drill string 32 to seal off well fluid in the annulus above and below it. The pressure is such as to allow the drill string and its tool joints to pass through it while maintaining a seal (stripping) in either direction. The actuator 258 also includes metal rings 268 at both ends of sleeve 260, each carrying a seal ring (not shown) thereabout to seal off the recess 250 to contain actuating fluid in the recess 250.
This patent proposes a retrievable ‘packing insert’ that is a custom component of the ‘riser isolation tool’. A problem with this solution is that it requires a custom installation of the riser isolation tool that limits the use of this packing insert to that type of subsea installation as described in the patent.